tkp4170 – process design, projectreport: 42 appendices: 23 conclusion a pulverized coal (pc) plant...

NTNU Faculty of Natural Sciences and Technology Norwegian University of Department of Chemical Engineering Science and Technology

TKP4170 – Process Design, Project

Title: Considerations for a New Coal-Fired Power

Plant on Svalbard

Location: Trondheim, Norway

Date:

November

21, 2013

Authors:

Aqeel Hussain

Reza Farzad

Anders Leirpoll

Kasper Linnestad

[email protected]

[email protected]

[email protected]

[email protected]

Supervisor: Sigurd Skogestad

Number of pages: 72

Report: 42

Appendices: 23

Conclusion A pulverized coal (PC) plant was found to be the best fit for a new power plant o n

Svalbard. The technology is commercially available, and no research and development is

required. A maximum boiler temperature of 00 was assumed, together with

subcritical pressure in the steam cycle. District heating from a backpressure steam

turbine was found to be a better option than a central heat pump, both practically and

economically.

-

TKP4170 Considerations for a New Coal-Fired Power Plant on Svalbard

i

Abstract Different types of coal-fired power plants were considered as options for a new power plant at

Svalbard. Conventional technology was found to be the best fit, and a pulverized coal plant was

modeled in detail. As the current plant does not have any flue gas treatment, the new plant was

designed to handle CO2, sulfur, NOx, dust particle and mercury emissions. In a literature search, a

seawater scrubber and amine solution carbon capture were found to be suitable for this task.

The plant was modeled in Aspen HYSYS according to design basis and data given by

Longyearbyen Bydrift. Four cases were considered and studied in detail. The base case

generates electric power from three steam levels, and utilizes the existing district heating

network in Longyearbyen to use remaining heat from the steam cycle. In the heat pump case,

electric power is generated from two steam levels, fully condensing the steam. It was assumed

that the power could be used in a central heat pump or in consumer bought heat pumps,

consuming the power more efficiently. The last two cases consider how increasing the steam

pressure or temperature affects the plants thermal efficiency.

Economic analysis was performed on all major equipment, using order-of-magnitude scaling and

the factorial method. Variable costs, revenues and working capital were estimated together with

capital costs to perform investment analysis on the investment.

By analyzing case study data from Aspen HYSYS it was found that the base case is preferable

over the heat pump case, both in efficiency and in economic perspective. The case studies on

steam temperature and pressure confirmed that higher values will give a rise in thermal

efficiency.

Further research is recommended on optimizing the steam cycle, as number of steam levels,

steam pressure and temperature highly affect the thermal efficiency. Research and development

is recommended on amine solution carbon capture, as the expense of carbon capture and

storage is the economic bottleneck of the project.


ii

Preface This project was written as a part of the M.Sc. degree in Chemical Engineering at the Norwegian

University of Science and Technology in the course TKP4170 Process Design Project.

We would like to thank our supervisor, Professor Sigurd Skogestad for his invaluable help,

insight and motivation throughout the project period.

We are deeply grateful, and his support has helped us throughout the whole project, providing

knowledge we will carry on in our degree.

Declaration of Compliance

We hereby declare that this is an independent report according to the exam regulations of the

Norwegian University of Science and Technology.

Trondheim, November 21, 2013

Aqeel Hussain

Reza Farzad

Anders Leirpoll

Kasper Linnestad


iii

Table of Contents Abstract i

Preface ii

1 Design Basis 1

2 Introduction to Coal-Fired Power Plants 2

2.1 Conventional Coal-Fired Power Plants 2

2.1.1 Supercritical Coal Fired Power Plants 3

2.2 Integrated Gasification Combined Cycle (IGCC) Coal-Fired Power Plants 4

2.3 Oxygen-Fired Coal Combustion Power Plants (Chemical Looping Combustion) 5

3 Introduction to Flue Gas Treatment 6

3.1 CO2 Capture 6

3.1.1 Post-Combustion Capture 6

3.1.2 Pre-Combustion Capture 7

3.1.3 Oxygen-Fired Combustion 8

3.1.4 Carbon Storage 8

3.1.5 Economics of CO2 Capture 8

3.2 Flue Gas Desulphurization 10

3.2.1 Wet scrubbing 10

3.2.2 Dry Scrubbing 11

3.3 NOx Removal 12

4 Process Descriptions 12

4.1 Current Plant at Svalbard 12

4.1.1 Boiler 13

4.1.2 Steam Cycle 13

4.1.3 District Heating 13

4.1.4 Gas Treatment 13

4.2 Proposed Pulverized Coal plant with Carbon Capture and Storage (Base Case) 14

4.2.1 Pulverized Coal Boiler 14


4.2.3 Flue Gas Treatment 15

4.2.4 District Heating 15

4.3 Case Studies 15

4.3.1 Base Case 15

4.3.2 Heat Pump Case 15

5 Flowsheet Calculations 15


iv

5.1 Base Case 15

5.1.1 Flow diagram 15

5.1.2 Stream Data 16

5.1.3 Compositions 17

5.1.4 Summary of Key Results 19

5.1.5 Steam Temperature 19

5.1.6 Steam Cycle Pressure 20

5.2 Heat Pump Case 20

5.2.1 Flow Diagram 21

5.2.2 Stream Data 22

5.2.3 Compositions 23

5.2.4 Summary of Key Results 24

5.2.5 Coefficient of performance 24

6 Cost Estimation 25

6.1 Capital Costs of Major Equipment 25

6.1.1 Pulverized Coal boiler 25

6.1.2 Heat exchangers 26

6.1.3 Turbines 26

6.1.4 Compressors 26

6.1.5 Pumps 27

6.1.6 Flue Gas Desulfurization 27

6.1.7 Carbon Capture Facility 27

6.1.8 Heat Pump Costs 27

6.1.9 Total Equipment Costs 28

6.2 Variable Costs 29

6.2.1 Labor 29

6.2.2 Diesel Costs 30

6.2.3 Cost of Coal 30

6.2.4 Operation and Maintenance 30

6.2.5 Chemicals 31

6.2.6 Total Variable Costs 31

6.3 Revenues 31

6.4 Working Capital 31

7 Investment Analysis 31

7.1 Base Case 31


v

7.2 Heat Pump Case 32

8 Discussion 33

8.1 Plant Choices 33

8.1.1 Plant Type 33


8.1.3 Flue Gas Treatment 34

8.2 Case Studies 34

8.2.1 Base Case 34

8.2.2 Steam Temperature 35

8.2.3 Steam Cycle Pressure 35

8.2.4 Heat Pump Case 35

8.3 Investments 35

8.3.1 Cost estimations 35

8.3.2 Investment analyses 36

9 Conclusion and Recommendations 37

References 38

List of symbols and abbreviations 41

Appendix A - Cost estimation for the base case A-1

A.1 Cost of major equipment A-1

A.2 Variable costs A-5

A.3 Revenues A-6

A.4 Working capital A-6

Appendix B - Cost estimation for the heat pump case B-1

B.1 Major Equipment B-1

B.2 Variable Costs B-5

B.3 Revenues B-6

B.4 Working Capital B-6

Appendix C - Cost estimation for the base case without carbon capture C-1

C.1 Cost of major equipment C-1

C.2 Variable Costs C-4

C.3 Revenues C-5

C.4 Working Capital C-5

Appendix D Net Calorific Value of the Coal on Svalbard D-1

Appendix E – Composite Curves E-1

E.1 Boiler E-1


vi

E.2 District Heat Exchanger E-1

E.3 Vacuum Condenser E-2

E.4 CO2 Cooler E-2

E.5 LP CO2-Cooler E-3

E.6 IP CO2-Cooler E-3

Appendix F – Aspen HYSYS Flowsheets F-1

F.1 Base Case F-1

F.2 Heat Pump Case F-2


1

1 Design Basis The design for the new plant was based upon the current plant data. It was assumed that the

electrical energy demand would double, and that the need for district heating would increase

with 50 %. A summary of the data from the current plant and the design basis for the new plant

are listed in Table 1.1.

Table 1.1: Plant data for the current plant and design basis for the new plant.

Current plant New plant

Electrical energy 4.8 MW 9.6 MW Thermal energy (district heating)

8.0 MW 12 MW

Coal 25000 ton/year 60000 ton/year (calculated) Diesel 390 000

liters/year 307 000 liters/year (average of the last four years)

The simplifications and assumptions that are made are listed below.

The coal is assumed to be pure carbon with the same net calorific value as the coal on

Svalbard (~7300 kcal/kg), shown in Figure D.1 in Appendix C .

The boiler is modeled as a combustion reactor with a maximum temperature of 00 ,

followed by a heat exchanger.

The boiler is assumed to combust the coal completely.

The boiler is assumed to have a minimum temperature approach of 10 , this is obtained

by adjusting the flow of water in the steam cycle.

The flue gas desulfurization is not included in the model.

The carbon capture facility is modeled as a pure component splitter with a given heat

requirement for re-boiling the rich amine solution in the stripper column.

The HP steam temperature and pressure are set to 00 and 165 bar respectively.

The outlet pressure of the HP steam turbine is set to 49 bar, and is reheated to 00 .

The vacuum pressure created by the condenser is set to 0.01 bar.

The seawater is assumed to be 4 .

The district heating network is modeled as heat exchangers with an inlet temperature of

1 0 , an outlet temperature of 0 and a pressure drop of 5 bar. This is obtained by

adjusting the flow of water in the district heating network.

The compressor train for the compression of carbon dioxide for storage is modeled as

two compressors and a pump with intercooling using heat exchanger with cold seawater.

The inter-stage pressures for the compressor train are found by trial and error to

yield the lowest amount of work needed.

The adiabatic efficiencies of all the compressors and pumps are assumed to be .

The split ratio between the LP steam turbine and the IP steam turbine are chosen to

yield a total district heating of 12 MW.

The amount of air blown into the boiler is chosen to yield a maximum combustion

temperature of 800 .


2

The amount of heat needed to the reboiler of the stripper is based on a 90% capture,

and an amount of heat needed per kilo removed ( 4

).

The amount of electricity needed for the heat pump is found by an estimate for the heat

pumps coefficient of performance (

) [1], and a basis of 12 MW for district

heating.

The price of electricity was assumed to be 1 NOK/kWh.

The price of district heating was assumed to be 0.5 NOK/kWh.

Constant yearly costs and revenues.

Constant depreciation rate of 10%.

Constant amount of depreciation of 20%.

0% tax on Svalbard.

2 Introduction to Coal-Fired Power Plants For more than 100 years, coal-fired power plants have generated the major portion of the

worldwide electric power [2] with a current (2011) market supply share of 41.2% [3]. Coal is

the largest growing source of primary energy worldwide, despite the decline in demand among

the OECD countries, due to China’s high increase in demand [4]. The Chinese coal consumption

and production account for more than 45% of both global totals, and it has been estimated that

their share will pass 50% by 2014 because of their high demand for cheap energy [4]. This will

drastically increase the world total CO -production which will contribute greatly to the global

warming and other environmental effects such as ocean acidification [5]. It will therefore be of

great importance to develop clean and efficient coal plants which can produce electricity that

can compete with the prices of the cheap, polluting coal plants that currently exists. Some

instances of such plants have been proposed as alternatives to the conventional coal-fired power

plant and they will be given an introduction in this report.

2.1 Conventional Coal-Fired Power Plants Conventional coal-fired power plants use pulverized coal (PC) or crushed coal and air as a fuel to

the furnace. The coal is pulverized by crushing and fed to the reactor at ambient pressures and

temperatures and burned in excess of air. The excess of air is introduced to lower the furnace

temperature which makes the equipment cheaper as it does not have to withstand extreme

temperatures, and it also reduces the formation of O . O is formed at high temperatures and

is a pollutant that has a negative effect on the health of humans besides contributing to acidic

precipitation [6]. The hot flue gas from the furnace is used to heat up the boiler which produces

high pressure (HP) steam. This steam is in turn expanded in a turbine arrangement that

generate electrical power. The low pressure (LP) steam is then condensed and re-fed to the

boiler. The hot flue gas contains pollutants and aerosols which have to be removed before the

gas is vented through the stack to the atmosphere. Pollutants that have to be removed include

mercury, O and O . The nitrous oxides are usually removed using selective catalytic

reduction (SCR) where ammonia is used as a reducing agent [7]. The sulfur, mercury and other

solid matter is normally removed as solid matter by reducing the sulfurous oxide using lime and

water, and then passing the flue gas through an electrostatic precipitator or a fabric filter. The

slurry is then collected for safe deposition. Conventional coal plants operating using subcritical


3

(sC) conditions, which will result in low overall plant efficiency [8]. A conceptual process flow

diagram of this power plant is shown in Figure 2.1.

Figure 2.1: Simplified process flow diagram for the conventional coal plant with district heating. HRSG = heat recovery steam generator. FGT = flue gas treatment (desulfurization, mercury removal, dust removal etc.)

2.1.1 Supercritical Coal Fired Power Plants

The efficiency of the plant can be increase by using supercritical (SC) steam conditions with

higher pressure. The plant efficiency is increasing both for increasing pressure drop and

increasing temperature. There is therefore a constant development of better equipment that can

withstand higher steam pressures and temperatures [8]. Some examples of conditions are listed

in

Table 2.1. The ultra supercritical configuration is currently under development and is expected

to be available in 2015 [8]. A typical heat recovery steam generator design is shown in Figure

2.2.

Boiler

FGT

HRSG

A

T 2-

x n

As

P w

D s n


4

Figure 2.2: Heat recovery steam generator cycle with three pressure levels, HP, IP and LP. HP = high pressure. IP = intermediate pressure. LP = low pressure.

Table 2.1: Some typical HP steam conditions [8]

Temperature

Pressure [bar]

Depleted < 500 < 115 Subcritical (sC) 500-600 115-170 Supercritical (SC) 500-600 230-265 Ultra supercritical ~730 ~345

2.2 Integrated Gasification Combined Cycle (IGCC) Coal-Fired Power Plants IGCC power plants feed compressed oxygen and a slurry of coal and water to a gasifier. The

gasifier converts the fuel to synthesis gas (syngas) which is then treated to remove sulfur,

mercury and aerosols. The syngas is then brought to a combustor with compressed air diluted

with nitrogen in a turbine. The flue gas is then used to create steam by passing it through an

HRSG. This steam is passed through a series of turbines, as with the conventional plant. The

efficiency gain this method has compared to the conventional plant is that the combustor

turbine operates at a very high temperature (~1500 ), but it also has to have an air separation

unit (ASU) to achieve reasonable conversion rates for the gasification process [9]. The IGCC

power plants require large investments because of all the advanced utilities such as a fluidized

bed reactor for gasification and an air separation unit. The IGCC power plants can achieve up to

3% higher efficiencies which can be worth the investment in the long run, especially for huge

power plants [8].

HP IP LP

nd ns


5

Figure 2.3: Simplified process flow diagram for the IGCC power plant.

2.3 Oxygen-Fired Coal Combustion Power Plants (Chemical Looping

Combustion) Oxygen-fired coal combustion power plants, also known as chemical looping combustion, burn

PC with pure oxygen which creates a flue gas that has a very high carbon dioxide concentration.

This has the advantage that the flue gas can be injected directly into storage after

desulfurization, and cleaning. This technology is currently under development and several pilot

plants have been built [10]. Unlike the other power plant designs, this design does not suffer a

significant loss in efficiency when carbon capture and storage (CCS) is implemented. For a

conventional power plant the loss in efficiency can be up to 14%, while the oxygen-fired power

plant only suffers losses of around 3% [8] [11]. Another advantage is that there will not be any

formation of nitrous oxides due to the lack of nitrogen in the feed, however the concentration of

sulfur oxide will increase due to the flue gas recycle. This is on the other hand not seen as a

major problem as sulfur oxide can be treated by introducing lime in the reactor. However this

technology is currently not available commercially.

Fluidized bed gasifier FGT

A HRSG P w

ASU

x n

As

S u

P w

T 2-

x n

N n


6

Figure 2.4: Simplified process flow diagram for the oxygen-fired coal combustion power plant.

3 Introduction to Flue Gas Treatment

3.1 CO2 Capture Energy supply from fossil fuels is associated with large emissions of CO and account for 75% of

the total CO emissions. CO emissions will have to be cut by 50% to 85% to achieve the goal of

restricting average global temperature increase to the range of to 4 [5]. Industry and

power generation have the potential to reduce the emission of greenhouse gases by 19% by

2050, by applying carbon capture and storage [12]. There are three basic systems for CO

capture.

Post-combustion capture

Pre-combustion capture

Oxygen fuelled combustion capture

3.1.1 Post-Combustion Capture

CO2 captured from flue gases produced by combustion of fossil fuel or biomass and air is

commonly referred to as post-combustion. The flue gases are passed through a separator where

CO is separated from the flue gases. There are several technologies available for post-

combustion carbon capture from the flue gases, usually by using a solvent or membrane. The

process that looks most promising with current technologies is the absorption process based on

amine solvents. It has a relatively high capture efficiency, a high selectivity of CO and the lowest

energy use and cost in comparison with other technologies. In absorption processes, CO is

captured using the reversible nature of chemical reactions of an aqueous alkali solution. Amine

solutions are most common for carbon capture. After cooling the flue gas it is brought into

contact with solvent in an absorber at temperatures of 40 to 0 . The regeneration of solvent

is carried out by heating in a stripper at elevated temperatures of 100 to 140 . This requires

a lot of heat from the process, and is the main reason why CO capture is expensive [13].

Membrane processes are used for CO capture at high pressure and higher concentration of

carbon dioxide. Therefore, membrane processes require compression of the flue gases; as a


A HRSG P w

ASU

x n

As

S u

T 2-

nj n

N n


7

consequence this is not a feasible solution with available technology as of 2013. However, if the

combustion is carried out under high pressure, as with the IGCC process, membranes can

become a viable option once they achieve high separation of CO [14].

Figure 3.1: Conceptual process flow diagram of the absorption process. HEX = heat-exchanger used to minimize the total heat needed for separation of carbon dioxide.

3.1.2 Pre-Combustion Capture

Pre-combustion capture involves reacting fuel with oxygen or air and adding water, and

converting the carbonaceous material into synthesis gas containing carbon monoxide and

hydrogen. During the conversion of fuel into synthesis gas, CO2 is produced via water-shift

reaction. CO2 is then separated from the synthesis gas using a chemical or physical absorption

process resulting in H2 rich fuel which can be further combusted with air. Pressure swing

adsorption is commonly used for the purification of syngas to high purity of H2, however, it does

not selectively separate CO2 from the waste gas, which requires further purification of CO2 for

storage. The chemical absorption process is also used to capture CO2 from syngas at partial

pressure below 1.5 MPa. The solvent removes CO2 from the shifted syngas by mean of chemical

reaction which can be reversed by high pressure and heating. The physical absorption process is

applicable in gas streams which have higher CO2 partial pressure or total pressure and also with

higher sulfur contents. This process is used for the capturing of both H2S and CO2, and one

commercial solvent is Selexol [8].

Absorption Regenerator

F u s

HEX

n u s

R bs b n

L n bs b n

Abs b n m -up

2

nj n

R -b


8

Figure 3.2: Schematic drawing of an integrated gasification combined cycle plant with pre-combustion carbon caption. Th e carbon monoxide from the gasifier is converted to carbon dioxide and hydrogen by reacting it with steam in the sh ift reactor. The carbon dioxide is captured in the carbon capture unit (CC, see Figure 3.1), and pure hydrogen is b u rned with nitrogen diluted air.

3.1.3 Oxygen-Fired Combustion

In oxygen-fired coal combustion, the flue gas is almost free of nitrogen-gases and after removal

of sulfur the flue gas is 90 % CO2, rest H2O. There is no need for further CO2-capture, and the CO2

can be compressed and stored [11].

3.1.4 Carbon Storage

After the carbon dioxide has been compressed it can be injected into storage. CO is usually

stored in geological formation at depths of 1000 m or more [15]. Hence high pressures are

required before injection, which has the advantage that CO can be injected as a supercritical

fluid. This will reduce the pipeline diameter and, consequently capital cost [16]. The oil industry

is experienced with geological difficulties, and may provide expertise on the geological

formation and how they will react to carbon dioxide injection. The storage site and reservoir has

to be closely monitored to ensure that the carbon dioxide does not escape into the atmosphere

or nearby drinking water supplies. With careful design of injection and appropriate monitoring

of well pressure and local CO -concentrations, it can be ensured that the injected carbon dioxide

remains underground for thousands of years [15].

3.1.5 Economics of CO2 Capture

CO2 capture is an expensive process both in capital costs and variable costs. Post combustion

absorption by amine solution can add as high as a 29% electrical power penalty even with state

of the art CO2 capture technology [8]. The capital costs depend highly on the flow rate of flue gas,

as this increases the regenerator and compressor size. The variable costs are also increased with

higher flue gas flow, as more sorbent is required, and the cost of CO2-transport and storage will


A HRSG P w

ASU

x n

As

S u

P w

T m sp

Shift reac-

tor

T 2-

nj n

CC

S m


9

increase [17]. Improving process configurations and solvent capacity can majorly reduce power

demand for the regenerator. Such improvements include: absorber intercooling, stripper

interheating, flashing systems and multi-pressure stripping, though all of these will come at the

expense of complexity and higher capital costs. Table 3.1 shows the development in MEA

absorption systems from year 2001 to 2006 [18].

Table 3.1: Economics of CO2 capture by MEA scrubbing [18].

Year of design 2001 2006 MEA [weight percent] 20 30 Power used [MWh/ton] 0.51 0.37 @ $ 80/MWh [$/ton CO2 removed] 41 29 Capital cost [$/ton CO2 removed per year] 186 106 @ 16%/year [$/ton CO2 removed] 30 17 Operating and maintenance cost [$/ton CO2 removed] 6 6 Total cost [$/ton CO2 removed] 77 52 Net CO2 removal with power replaced by gas [%] 72 74

The environmental impact is commonly expressed as cost per pollutant removed or cost per

pollutant avoided. Cost of CO2 per tom removed is different from cost of CO2 avoided and cost of

CO2 avoided is given as [19] :

cost o CO a oided ( tonne⁄ ) ( h⁄ ) ( h⁄ )

(tonne CO h⁄ ) (tonne CO h⁄ ) (1)

Table 3.2 shows the cost variability and representative cost values for power generation and CO2

capture, for the three fuel systems respectively. The cost of electricity is lowest for the NGCC,

regardless of CO2 capture. Pulverized Coal plant has lower capital cost without capture while

IGCC plant has lower cost when current CO2 capture is added in the system.


10

Table 3.2: Summary of reported CO2 emissions and costs for a new electric power plant with and without CO2 capture b ase don current technology (excluding CO2 transport and storage costs) [20].

MWref = reference plant net output Rep . value = representative value NGCC = natural gas combined cycle plant.

Cost and Performance Measures

PC Plant IGCC Plant NGCC Plant

Range low-high

Rep. value

Range low-high

Rep. value

Range low-high

Rep. value

Emission rate w/o capture [kg CO2/MWh]

722-941 795 682-846 757 344-364

358

Emission rate with capture [kg CO2/MWh]

59-148 116 70-152 113 40-63 50

Percent CO2 reduction per kWh [%]

80-93 85 81-91 85 83-88 87

Capital cost w/o capture [$/kW]

1100-1490

1260 1170-1590

1380 447-690

560

Capital cost with capture [$/kW]

1940-2580

2210 1410-2380

1880 820-2020

1190

Percent increase in capital cost [%]

67-87 77 19-66 36 37-190 110

Cost of CO2 avoided [$/t CO2]

42-55 47 13-37 26 35-74 47

Cost of CO2 captured [$/t CO2]

29-44 34 11-32 22 28-57 41

Power penalty for capture [% MWref]

22-29 27 12-20 16 14-16 15

Thermal efficiency w/o capture [8]

36.8%-39.3%

38.1% 39.0%-42.1%

40.2% 50.2% 50.2%

Thermal efficiency w/ capture [8]

26.2%-28.4%

27.3% 31.0%-32.6%

31.6% 42.8% 42.8%

3.2 Flue Gas Desulphurization SO2 has a harmful effect both on humans and the environment. Exposure to higher

concentrations of SO2 is the cause of many harmful diseases. SO2 affects the environment by

reacting into acids and is a major source of acid rain [21]. Combustion of sulfur-containing

compounds such as coal is a major source of SO2 generation. Removal of sulfur from solid fuels is

not practical, so the sulfur is removed from the flue gas after combustion of coal. The removal of

sulfur oxide from the flue gasses is achieved by physical or chemical absorption process [22].

There are two commonly used industrial processes for the desulphurization of flue gasses [23],

wet and dry scrubbing.

3.2.1 Wet scrubbing

In wet scrubbing, a solvent is used for the absorption of SO2. Typically water is considered to be

the cheapest sol ent It’s washing capacity howe er is ery limited and huge quantity of water

has to be used. Approximately 75 tons of water is used per ton of flue gas, and even then 5% of

SO2 remains [22].

In advanced processes, flue gas is treated with an alkaline slurry in an absorber, where SO2 is

captured, shown in Figure 3.3. The most commonly used slurry is composed of limestone, which


11

reacts with the sulfur. The sulfur removal efficiency is 98 % for wet slurry scrubbing processes.

Carbon dioxide removal units include a polishing scrubber which lowers flue gas SO2 content

from 44 ppmv to 10 ppmv [8].

Figure 3.3: Flue gas desulfurization via wet scrubbing using limestone slurry [24].

Wet scrubbing process is mostly used with higher sulfur contents with economic efficiency of 95

to 98%. The main disadvantage of wet scrubbing is acidic environment which can be corrosive.

Therefore, corrosion resistant material is required for the construction which increases capital

cost of the plant. The other disadvantage includes consumption of large quantity of water for the

process.

3.2.2 Dry Scrubbing

Dry scrubbing is useful for coal with lower sulfur content. It also has the major advantage of

maintaining a higher temperature of the emission gasses, while wet scrubbing decreases the

temperature to that of water used [21]. Lime is normally used as sorbent-agent during the dry

scrubbing process. The dry sorbent reacts with the flue gas at 1000 to remove SO2. In dry

scrubbing adiabatic saturation approach is normally applied. Adiabatic saturation is required to

achieve high SO2 removal, thereby carefully controlling the amount of water [21].

Figure 3.4: Flue gas desulfurization via dry scrubbing using limestone [24].

Flue Gas

Lime + Water

Oxidation Air Solids for

Dewatering

Wet Desulfurized

Flue Gas

Flue Gas

Desulfurisation

Scrubber

Flue Gas

Lime + Water

Solids for

Disposal

Desulfurized

Flue Gas Flue Gas

Desulfurisation

Spray Dryer

Electrostatic

Precipitator


12

Relatively poor conversion is the main disadvantage of dry sorbent process, which increases the

operational costs. Dry scrubbing uses a minimal amount of water, and leaves the flue gas dry,

reducing risk of corrosion. Relatively dry calcium sulfite is obtained as by-product with fly ash

[21].

3.3 NOx Removal Selective catalytic reduction (SCR) approach is applied for removal of NOx, where the flue gas is

reduced with ammonia over a catalyst to nitrogen and water. The SCR has a efficiency of 80 to 90

% for NOx removal. The optimal temperature range is 0 7 0 , with vanadium and titanium

as catalyst, and the following reaction is carried out during the process:

4 4 O O 4 O (2)

Ammonia is either injected in pure form under pressure or in an aqueous solution. Instead of

ammonia, urea can also be used for the process. The main challenge of the process is full

conversion as emission of the NH3 is highly undesirable. The unreacted NH3 can also oxidize SO2

to SO3 that further reacts with NH3 to form ammonium bisulfate. Ammonium bisulfate is a sticky

solid material which can plug the equipment. The catalyst activity is very critical with SCR

because catalyst can cost up to 1 0 of the capital cost [7].

4 Process Descriptions

4.1 Current Plant at Svalbard A process flow diagram for the existing plant at Svalbard is shown in Figure 4.1.

Figure 4.1: Process flow diagram of current plant at Svalbard

Boiler

District heating

Coal

Air

Ash Main Water

Pump

Sea water Pump

Sea water

Condenser

Condensing Steam Turbine

District Heat Water Pump

Flue Gas Back Pressure Steam Turbine

𝑝 4 bar𝑇 4 0

𝑝 0 0 bar𝑇 4

𝑝 1 bar𝑇

𝑝 9 bar𝑇 0

𝑝 1 bar𝑇 1 0

𝑝 1 bar𝑇 1 0

𝑝 𝑇 ambient

𝑝 bar𝑇 0


13

4.1.1 Boiler

Coal is crushed and fed to the boiler along with air, where it combusts at high temperatures

forming flue gas and ash. The air is blown into the boiler by fans. Water is circulated through the

evaporator-drums in the boiler to yield pressurized steam. The flue gas is sent directly to the

stack and out to the atmosphere.

4.1.2 Steam Cycle

The hot steam from the boiler is split into two streams, one of which is sent to a condensing

steam turbine, the other to a backpressure steam turbine. The steam from the condensing steam

turbine is quenched in a condenser that is cooled with seawater; this allows the outlet pressure

from the turbine to be relatively low, depending on how much it is cooled. The backpressure

steam turbine has a relatively high backpressure, which yields moderately high temperatures in

the outlet stream. This heat is exploited by heating up cold water from the district heating

network. The two different streams are then combined, sent through a pump and back to the

boiler.

4.1.3 District Heating

The district heating water circulates Longyearbyen, and is used to heat houses and tap water,

before it is sent back to the power plant for reheating. The water is pumped to a heat exchanger

where it is reheated by the condensing steam from the backpressure steam turbine. After which

it is sent back to the district heating network.

4.1.4 Gas Treatment

The flue gas is currently not treated before it is sent trough the stack to the atmosphere.


14

4.2 Proposed Pulverized Coal plant with Carbon Capture and Storage (Base

Case)

Figure 4.2: Process flow diagram of the proposed design. FGT = flue gas treatment unit, and CC = carbon capture unit.

4.2.1 Pulverized Coal Boiler

Coal is pulverized and fed to the boiler along with air, where it combusts at high temperatures

forming flue gas and ash. Water is circulated through the evaporator-drums in the boiler to yield

high pressure (HP) steam, through the re-heater to re-heat the intermediate pressure (IP)

steam, while re-boiler amine solution is fed through the economizer, recovering heat from the

flue gas.

4.2.2 Steam Cycle

HP steam is run through a HP turbine, and the re-heated IP steam is run through a split to the IP

turbine or the low pressure (LP) turbine. After the LP turbine, the steam condenses using

seawater from the seawater pump. Because of the low temperature of the seawater, low

pressures are obtained. After the IP turbine, the water still has a high temperature and pressure,

which is used for district heating. Residual condensed steam from both the IP and LP turbine is

pumped back up to a high pressure and once again fed into the boiler evaporator drums.

Boiler

District heating

FGT

CC

Coal

Air

Ash Main Water

Pump Sea water

Pump

Sea water

Vacuum Condenser

Condensing Steam Turbine

Low Pressure Water Pump

Back Pressure Steam Turbine

High Pressure Turbine

District Heat Water Pump

Low Pressure 𝑪𝑶𝟐 Compressor

intermediate Pressure 𝑪𝑶𝟐 Compressor

High Pressure 𝑪𝑶𝟐 Pump

Clean

Flue Gas

Flue Gas

𝑪𝑶𝟐

𝑝 𝑇 ambient

𝑝 1 bar𝑇 0

𝑝 1 bar𝑇

𝑝 1 bar𝑇 1 0

𝑝 bar𝑇 1 0

𝑝 41 bar𝑇 1 0

𝑝 100 bar𝑇 1

𝑝 1 bar𝑇

𝑝 1 bar𝑇

𝑝 bar𝑇 0

𝑝 bar𝑇 0

𝑝 bar𝑇 1 0

𝑝 49 bar𝑇 00

𝑝 1 bar𝑇 00

𝑝 1 bar𝑇 1 0

𝑝 0 001 bar𝑇


15

4.2.3 Flue Gas Treatment

The flue gas out of the boiler is first desulfurized in the flue gas desulfurization unit (FGD), using

a seawater scrubber. The seawater is used to cool steam and CO2 earlier in the process, and then

fed to the seawater scrubber. As the concentration of sulfur in the water out is low, it can safely

be pumped back to the ocean. As the flue gas is quenched through seawater, dust particles and

mercury is also removed.

After FGD, the flue gas goes through the carbon capture (CC) facility, using an amine solution.

Flue gas with low CO2-content is sent out to the environment, while the captured CO2 is sent to

compression and storage. Here the CO2 is cooled with seawater and compressed two times,

before being pumped as a supercritical fluid down into geological formations.

4.2.4 District Heating

The proposed pulverized coal power plant will use the same district heating network as is

already built on Svalbard, giving a steam split-factor between IP and LP turbines. The district

heating water circulates Longyearbyen, and is used to heat houses and tap water. After being

used, the water is sent back to the power plant. The cycle introduces a pressure drop, which is

equalized by the district heating water pump.

4.3 Case Studies In the report two different cases will be studied, one using the existing district heating loop on

Svalbard, another introducing a central heat pump.

4.3.1 Base Case

The base case uses the current district heating network on Svalbard, and produces 12 MW of

district heating, with double the current electric power, giving 9.6 MW of electric energy. The

split of steam to the backpressure IP turbine for district heating and LP turbine for pure electric

generation is adjustable, and was adjusted to fit the design basis in Table 1.1, using as little coal

as possible.

4.3.2 Heat Pump Case

The heat pump case is an attempt at maximizing electric energy produced, to use the electric

energy in heat pumps instead of district heating. This model has the possibility of selling excess

electric power to the neighboring town of Barentsburg, but is highly dependent on good

coefficient of performance for the heat pump. Investment analysis is performed on both cases,

using the same amount of coal, to compare them to each other.

5 Flowsheet Calculations

5.1 Base Case The plant is modeled using Aspen HYSYS, based on the results rom the report “Cost and

Per ormance Baseline or Fossil Energy Plants” by the ational Energy Technology Laboratory

[8].

5.1.1 Flow diagram

The process flow diagram from the Aspen HYSYS model is shown in Figure 5.1, a larger figure is

shown in Appendix F .


16

Figure 5.1: The process flow diagram from the Aspen HYSYS model for the base case.

5.1.2 Stream Data

The important stream data for the different streams in the Aspen HYSYS model are shown in

Table 5.1.


17

Table 5.1: Stream data for the base case, calculated in Aspen HYSYS.

Stream name Vapor fraction

Temperature [ ]

Pressure [bar]

Mass flow [kg/s]

Air 1.00 10.00 1.0 70.4

Coal 0.00 10.00 1.0 1.90

Flue gas 1.00 799.99 1.0 72.3

Slurry 0.00 799.99 1.0 0.00

1 0.00 40.36 3.0 9.08

2 0.00 41.30 165.0 9.08

3 1.00 600.00 165.0 9.08

4 1.00 407.07 49.0 9.08

5 1.00 600.00 49.0 9.08

6 1.00 600.00 49.0 4.87

7 0.90 5.88 0.0 4.87

8 0.00 5.88 0.0 4.87

9 0.00 5.99 10.0 4.87

10 1.00 600.00 49.0 4.21

13 0.00 80.00 3.0 4.21

14 0.00 40.44 3.0 9.08

D1 0.00 80.00 3.0 63.8

D4 0.00 80.00 3.0 63.8

D2 0.00 80.04 8.0 63.8

D3 0.00 120.00 8.0 63.8

11 1.00 349.87 8.0 4.21

12 0.00 120.00 8.0 4.21

Reboiler in 0.00 120.00 2.0 9.93

Reboiler out 1.00 120.00 2.0 9.93

Cleaned Gas 1.00 79.42 1.0 65.3

CO2 for compression 1.00 79.40 1.0 6.97

MP CO2 1.00 177.95 41.0 6.97

MP CO2 liquid 0.00 6.00 41.0 6.97

HP CO2 liquid 0.00 13.31 100.0 6.97

SW 1 0.00 3.00 1.2 2560

SW 2 0.00 4.00 1.2 2560

SW 0 0.00 3.00 1.0 2560

SW5 0.00 4.39 1.2 2560

LP CO2 1.00 163.23 6.1 6.97

LP CO2 cooled 1.00 10.00 6.1 6.97

SW4 0.00 4.13 1.2 2560

Cold CO2 for compression

1.00 10.00 1.0 6.97

SW3 0.00 4.04 1.2 2560

Cooler Flue Gas 1.00 79.40 1.0 72.3

5.1.3 Compositions

The composition of each stream from the Aspen HYSYS model is shown in Table 5.2.


18

Table 5.2: Composition data for the base case, calculated in Aspen HYSYS, where is the mole fraction of component .

Stream name

CO O C

Air 0.000 0.000 0.210 0.790 0.000

Coal 0.000 0.000 0.000 0.000 1.000

Flue gas 0.000 0.065 0.145 0.790 0.000

Slurry 0.000 0.065 0.145 0.790 0.000

1 1.000 0.000 0.000 0.000 0.000

2 1.000 0.000 0.000 0.000 0.000

3 1.000 0.000 0.000 0.000 0.000

4 1.000 0.000 0.000 0.000 0.000

5 1.000 0.000 0.000 0.000 0.000

6 1.000 0.000 0.000 0.000 0.000

7 1.000 0.000 0.000 0.000 0.000

8 1.000 0.000 0.000 0.000 0.000

9 1.000 0.000 0.000 0.000 0.000

10 1.000 0.000 0.000 0.000 0.000

13 1.000 0.000 0.000 0.000 0.000

14 1.000 0.000 0.000 0.000 0.000

D1 1.000 0.000 0.000 0.000 0.000

D4 1.000 0.000 0.000 0.000 0.000

D2 1.000 0.000 0.000 0.000 0.000

D3 1.000 0.000 0.000 0.000 0.000

11 1.000 0.000 0.000 0.000 0.000

12 1.000 0.000 0.000 0.000 0.000

Reboiler in 1.000 0.000 0.000 0.000 0.000

Reboiler out 1.000 0.000 0.000 0.000 0.000

Cleaned Gas 0.000 0.000 0.155 0.845 0.000

CO2 for compression

0.000 1.000 0.000 0.000 0.000

MP CO2 0.000 1.000 0.000 0.000 0.000

MP CO2 liquid

0.000 1.000 0.000 0.000 0.000

HP CO2 liquid

0.000 1.000 0.000 0.000 0.000

SW 1 1.000 0.000 0.000 0.000 0.000

SW 2 1.000 0.000 0.000 0.000 0.000

SW 0 1.000 0.000 0.000 0.000 0.000

SW5 1.000 0.000 0.000 0.000 0.000

LP CO2 0.000 1.000 0.000 0.000 0.000

LP CO2 cooled

0.000 1.000 0.000 0.000 0.000

SW4 1.000 0.000 0.000 0.000 0.000


0.000 1.000 0.000 0.000 0.000

SW3 1.000 0.000 0.000 0.000 0.000

Cooler Flue Gas

0.000 0.065 0.145 0.790 0.000


19

5.1.4 Summary of Key Results

A summary of the key results from the flowsheet calculation is shown in Table 5.3. In addition,

the composite curves for all the heat exchangers are shown in Appendix E

Table 5.3: A summary of the results from the simulation of the base case.

Object Value

District heating power output 12.0 MW Net electrical power output 9.6 MW Amount of coal needed 60000 ton/year (1.90 kg/s) Thermal efficiency 34.7% Heat needed for CO2-removal 22.6 MW

5.1.5 Steam Temperature

A case study was performed on the model in Aspen HYSYS, which studies the effect of the

temperature of the steam. The thermal efficiency is calculated as:

thermal se ul energy out

se ul energy in

electric district heat

C C (3)

Where thermal is the thermal efficiency, electric is the net electric power produced, district heat is

the power provided to district heating, C is the mass flow of coal and C is the coal’s net

calorific value. In the rest of the report, the thermal efficiency is used exclusively. The results are

shown in Figure 5.2. The steam temperature’s e ect on e iciency is highly dependent on the

boiler design, which can be seen from the composite curves in Figure 5.3.

Figure 5.2: The effect on net power output and thermal efficiency as a function of temperature in the combustion ch amber of the boiler.

0.336

0.338

0.340

0.342

0.344

0.346

0.348

0.350

0.352

0.354

0.356

9.00

9.20

9.40

9.60

9.80

10.00

10.20

500 550 600 650 700 750

Th

erm

al

Eff

icie

ncy

Po

we

r [M

W]

Steam Temperature [

Electrical Power

Base Case ElectricalPowerEfficiency

Base Case Efficiency


20

Figure 5.3: Plot o hot and cold composite cur e or the pul erized coal boiler The pinch temperature is set to 10

5.1.6 Steam Cycle Pressure

A case study was performed on the model in Aspen HYSYS, which studies the effect of the

highest pressure in the steam cycle. The results are shown in Figure 5.4.

Figure 5.4: The effect on net power output and thermal efficiency as a function of maximum pressure in the steam cycle.

5.2 Heat Pump Case The heat pump case is modeled in a similar manner as the base case, but without the district

heating network and the split between the LP steam turbine and the IP steam turbine.

0

100

200

300

400

500

600

700

800

0 10 20 30 40 50 60

Te

mp

era

ture

[

Heat transfered [MW]

Cold Composite Curve

Hot Composite Curve

0.336

0.338

0.340

0.342

0.344

0.346

0.348

0.350

0.352

0.354

0.356

9.00

9.20

9.40

9.60

9.80

10.00

10.20

100 120 140 160 180 200 220 240 260 280 300 320 340

Th

erm

al

eff

icic

en

cy

Po

we

r [M

W]

Highest pressure [bar]

Electrical Power

Base Case ElectricalPowerEfficiency



21

5.2.1 Flow Diagram

The process flow diagram from the Aspen HYSYS model is shown in Figure 5.5.

Figure 5.5: The process flow diagram from the Aspen HYSYS model for the heat pump case.


22

5.2.2 Stream Data

The important stream data for the different streams in the Aspen HYSYS model are shown in

Table 5.4.

Table 5.4: Stream data for the heat pump case, calculated in Aspen HYSYS.

Stream name Vapor fraction

Temperature ]

Pressure [bar]

Mass flow [kg/s]

Air 1.00 10.00 1.01 70.4

Coal 0.00 10.00 1.00 1.90

Flue gas 1.00 799.99 1.00 72.3

ash 0.00 799.99 1.00 0.00

1 0.00 5.88 0.01 9.09

2 0.00 6.65 165.00 9.09

3 1.00 600.00 165.00 9.09

4 1.00 407.07 49.00 9.09

5 1.00 600.00 49.00 9.09

7 0.90 5.88 0.01 9.09

8 0.00 5.88 0.01 9.09

Flue gas cooled 1.00 60.50 1.00 72.3

Reboiler in 0.00 120.0 1.01 9.93

Reboiler out 1.00 120.0 1.01 9.93

To atmosphere 1.00 60.53 1.00 65.3

CO2 for compression 1.00 60.50 1.00 6.97

LP CO2 1.00 163.23 6.10 6.97

LP CO2 cooled 1.00 10.00 6.10 6.97

MP CO2 1.00 177.95 41.00 6.97

MP CO2 liquid 0.00 6.00 41.00 6.97

HP CO2 liquid 0.00 13.31 100.00 6.97

SW 1 0.00 3.00 1.20 3183

SW 2 0.00 4.50 1.20 3183

SW 0 0.00 3.00 1.00 3183


1.00 10.00 1.00 6.97

SW 3 0.00 4.52 1.20 3183

SW 4 0.00 4.60 1.20 3183

SW 5 0.00 4.80 1.20 3183


23

5.2.3 Compositions

The composition of each stream from the Aspen HYSYS model is shown in Table 5.5.

Table 5.5: Stream data for the heat pump case, calculated in Aspen HYSYS, where is the mole fraction of component .

Stream name

CO O C

Air 0.000 0.000 0.210 0.790 0.000

Coal 0.000 0.000 0.000 0.000 1.000

Flue gas 0.000 0.065 0.145 0.790 0.000

ash 0.000 0.065 0.145 0.790 0.000

1 1.000 0.000 0.000 0.000 0.000

2 1.000 0.000 0.000 0.000 0.000

3 1.000 0.000 0.000 0.000 0.000

4 1.000 0.000 0.000 0.000 0.000

5 1.000 0.000 0.000 0.000 0.000

7 1.000 0.000 0.000 0.000 0.000

8 1.000 0.000 0.000 0.000 0.000

Flue gas cooled

0.000 0.065 0.145 0.790 0.000

Reboiler in 1.000 0.000 0.000 0.000 0.000

Reboiler out 1.000 0.000 0.000 0.000 0.000

To atmosphere

0.000 0.000 0.155 0.845 0.000

CO2 for compression

0.000 1.000 0.000 0.000 0.000

LP CO2 0.000 1.000 0.000 0.000 0.000

LP CO2 cooled

0.000 1.000 0.000 0.000 0.000

MP CO2 0.000 1.000 0.000 0.000 0.000

MP CO2 liquid

0.000 1.000 0.000 0.000 0.000

HP CO2 liquid

0.000 1.000 0.000 0.000 0.000

SW 1 1.000 0.000 0.000 0.000 0.000

SW 2 1.000 0.000 0.000 0.000 0.000

SW 0 1.000 0.000 0.000 0.000 0.000


0.000 1.000 0.000 0.000 0.000

SW 3 1.000 0.000 0.000 0.000 0.000

SW 4 1.000 0.000 0.000 0.000 0.000

SW 5 1.000 0.000 0.000 0.000 0.000


24

5.2.4 Summary of Key Results

A summary of the key results from the flowsheet calculation is shown in Table 5.6. In addition,

the composite curves for all the heat exchangers are shown in Appendix E

Table 5.6: A summary of the results from the simulation of the heat pump case. A coefficient of performance of 3 was u sed to obtain these results.

Object Value District heating power output 12.0 MW Net electrical power output 9.4 MW Amount of coal needed 60000 ton/year (1.90 kg/s) Thermal efficiency 34.3% Heat needed for CO2-removal 22.6 MW

5.2.5 Coefficient of performance

The o erall thermal e iciency was calculated or di erent alues o the heat pump’s coe icient

of performance. A plot of the result is shown in Figure 5.6.

Figure 5.6: A plot o o erall thermal e iciency as a unction o the heat pump’s coe icient o per ormance

0.20

0.25

0.30

0.35

0.40

1 2 3 4 5 6 7 8 9 10

Eff

icie

ncy

Coefficient of performance

Efficiency



25

Figure 5.7: An excerpt of Figure 5.6 for comparison with Figure 5.2 and Figure 5.4.

As can be seen, a high coefficient of performance is required to compete with the base case. This

is further addressed in Section 8.2.4.

6 Cost Estimation

6.1 Capital Costs of Major Equipment Cost estimations were performed on major equipment for both the district heating case and the

heat pump case. In this section, only costs for the base case are shown, while detailed cost

estimations for both cases are shown in Appendix A and Appendix B . Cost estimations were also

performed for the base case but without district heating, this is shown in Appendix C .

6.1.1 Pulverized Coal boiler

The pulverized coal (PC) boiler cost was estimated by an order-of-magnitude scaling, using the

following equation [25]:

(

)

(

)

(4)

where is the cost of a plant with capacity , is the cost of a plant with capacity and is

the exponent, which can be assumed to be 0.67 for PC plant boilers [26]. The capacity used for

calculations was electrical power produced in MW, assuming no district heating. By using data

for a PC plant with CO2-capture [8], a cost of 07 00 (on Jan. 2013 basis by using CEPCI

[27]) was obtained. This includes costs for piping, instrumentation and equipment erection. This

0.336

0.338

0.340

0.342

0.344

0.346

0.348

0.350

0.352

0.354

0.356

2.7 2.9 3.1 3.3 3.5 3.7

Eff

icie

ncy

Coefficient of performance

Efficiency



26

cost has some uncertainty, with the original boiler being 50 times larger than the boiler

estimated.

6.1.2 Heat exchangers

The heat exchangers were assumed to be U-tube shell and tube exchangers, with the following

formula and tabulated values from Sinnott [25]:

4 000 4 (5)

where and are cost constants, the capacity parameter is the heat transfer area of the

exchanger in m and is the exponent. To calculate the required area, the overall heat transfer

coefficient was estimated from tables in Sinott [25].For given values of exchanger area,

constants and exponent, the cost of the exchangers were estimated, shown in Table 6.1. Here the

Vacuum Condenser was divided into several exchangers with capacity inside the 1000 m2 limit

of formula (5). The values are on Jan. 2013 basis by using CEPCI [27]. This does not include any

material factors, piping, instrumentation or other cost factors.

Table 6.1: Estimations of heat exchanger costs, this does not include any material factors, piping, instrumentation or other cost factors.

Heat Exchanger U [W/m2K]

Capacity [m2]

Cost [$]

Heat Exchanger for District Heating 1200 105 43 500

Four Vacuum Condensers 1200 4 9 4 977 200

CO2 Cooler 50 313 83 300 Low Pressure CO2 Cooler 100 213 63 100

Intermediate Pressure CO2 Condenser 700 108 43 900

6.1.3 Turbines

The costs of the steam turbines were estimated using the same formula as for the boiler, using

an exponent of 0.67 for steam turbines [26]. The cost of the High Pressure, Intermediate

Pressure and Low Pressure turbines were estimated, and are shown in Table 6.2 on Jan. 2013

basis by using CEPCI [27]. This does not include any material factors, piping, instrumentation or

other cost factors.

Table 6.2: Estimation of turbine cost, this does not include any material factors, piping, instrumentation or other cost f actors.

Turbines Capacity [kW]

Cost [$]

High Pressure Turbine 2991 951 300

Intermediate Pressure Turbine 2097 749 900

Low Pressure Turbine 6785 1 646 900

6.1.4 Compressors

The compressors for CO2-injection were assumed to be centrifugal and estimated from tabulated

values in Sinnott using the following formula, inserted for constants and exponent:

490 000 1 00 (6)

where is the size parameter, here compressor power in . For given values of power,

constants and exponent the cost of Low Pressure CO2 Compressor and Intermediate Pressure


27

CO2 Compressor were estimated to be 400 and 1 700, respectively. The values are

on a Jan. 2013 basis by using CEPCI [27], and do not include any material factors, piping or other

cost factors.

6.1.5 Pumps

In similar fashion to compressor estimations, pumps were assumed to be single-stage

centrifugal pumps, with the following formula and tabulated values from Sinnott [25]:

900 0 (7)

where the capacity parameter is liters feed per second. For given values of feed, constants and

exponent, the cost of the pumps were estimated, shown in Table 6.3. The values are on Jan. 2013

basis by using CEPCI [27]. The cost of the Seawater pump has a large uncertainty, due to it being

outside of the interval of Formula (7). This does not include any material factors, piping,

instrumentation or other cost factors.

Table 6.3: Estimations of pump costs, this does not include any material factors, piping, instrumentation or other cost f actors.

Pump Capacity [L s-1]

Cost [$]

High Pressure CO2 Pump 7.8 14 300

Main Water Pump 9.1 14 600

Low Pressure Water Pump 4.8 13 500

District Heat Water Pump 66.2 27 600

Seawater Pump 2501 421 800

6.1.6 Flue Gas Desulfurization

For flue gas desulfurization a wet scrubber was chosen, using wastewater from seawater heat

exchangers. Scaling was performed in a similar manner to that of the boiler for a flue gas wet

desulfurization unit [28]. Using plant produced electricity in MW as a scaling variable, a cost of

9 400 (on Jan. 2013 basis by using CEPCI [27]) was obtained. This includes piping,

instrumentation and other cost factors.

6.1.7 Carbon Capture Facility

Cost of the carbon capture (CC) facility was based on a plant utilizing amine solution technology.

The capital costs of the CC units were estimated as a given percentage of the capital cost of the

PC plant without carbon capture. A conservative estimate may be found in Table 3.2 as 87%.

Hence the capital cost of the CC facility was estimated to be 97 0 000 (on Jan. 2013 basis by

using CEPCI [27]). This includes piping, instrumentation and other cost factors.

6.1.8 Heat Pump Costs

For the heat pump case, heat pump costs were estimated using a cost estimate based on the

thermal output of the heat pump [29]:

14000 OK

district heating (8)

The estimated capital cost of the heat pump is OK 1 000 000, which includes installation and

other cost factors. This cost is not used in the base case.


28

6.1.9 Total Equipment Costs

In the total equipment costs, all equipment was modified using the following formula and factors

from Sinnott [25]:

∑ , ,

(1 ) ( ) (9)

where is the total cost of the plant, including engineering costs, , , is purchased cost of

equipment i in carbon steel, is the total number of pieces of equipment, is the installation

factor for piping, is the materical factor for exotic alloys, is the installation factor for

equipment erection, is the installation factor for electrical work, is the installation factor for

instrumentation and process control, is the installation factor for civil engineering work, is

the installation factor for structures and buildings and is the installation factor for lagging,

insulation, and paint. A typical value for the factors combined for a piece of equipment in carbon

steel is 3.2, and 3.7 for 304 stainless steel.

For equipment handling CO2 and seawater, 304 stainless steel was found to be resistant enough

[25], while other pieces of equipment were estimated as carbon steel. To calculate the total fixed

capital cost, , the following formula and factors from Sinnott were used [25]:

(1 O )(1 DE ) (10)

where O is the offsite cost, DE is design and engineering cost and is contingenacy costs. The

total fixed capital costs are summarized in Table 6.4 on U.S. Gulf Coast Jan. 2013 basis.


29

Table 6.4: Total estimated equipment costs, with material factors, piping and other cost factors included.

The total equipment cost was calculated from $ U.S. Gulf Coast Jan. 2013 basis into Norwegian

Krone 2013 basis (NOK) [30], yielding NOK 1 977 964 700 as total equipment costs. The

corresponding estimate without a carbon capture facility was estimated as NOK 799 069 800.

For the heat pump case, the total equipment cost was estimated to be NOK 2 798 851 400.

6.2 Variable Costs

6.2.1 Labor

Number of required operators per shift is given by [31]:

( 9 0 ) (11)

where is number of process units at the plant. With 12 process units, it yields 4 operators

per shift.

Equipment Cost [$]

Pulverized Coal Boiler 40 569 200

Heat Exchanger for District Heating 139 200

Vacuum Condenser 3 126 900

CO2 Cooler 306 400

Low Pressure CO2 Cooler 232 300

Intermediate Pressure CO2 Condenser 161 600

Total Exchanger Costs 3 966 500

High Pressure Turbine 3 044 200

Intermediate Pressure Turbine 2 399 700

Low Pressure Turbine 5 270 100

Total Turbine Costs 10 714 000

Low Pressure CO2 Compressor 9 760 700

Intermediate Pressure CO2 Compressor 9 868 800

Total Compressor Costs 19 629 500

High Pressure CO2 Pump 52 500

Main Water Pump 46 800

Low Pressure Water Pump 43 100

District Heat Water Pump 88 300

Seawater Pump 1 552 100

Total Pump Costs 1 782 800

Wet Flue Gas Desulfurization 5 896 400

Carbon Capture Facility 97 900 000

Total Fixed Capital Costs 341 028 400

Total Fixed Capital Costs [NOK] 1 977 964 700


30

Table 6.5: Estimation of the labor costs.

Labor

Number of units 20

Number of operators 4

Shifts per day 6

Employed operators 24

Salary per year NOK 433 000

Labor costs per year NOK 10 392 000

6.2.2 Diesel Costs

Diesel is burned to generate power and district heating when the coal plant is down for

maintenance and for peak loads. Yearly diesel costs are shown in Table 6.6.

Table 6.6: Estimated yearly diesel costs [32].

Diesel consumption

Diesel consumption in 2012 [l] 390417




Mean diesel consumption [l] 307585

Price of diesel [NOK/l] NOK 12.00

Diesel costs per year NOK 3 691 000

6.2.3 Cost of Coal

Yearly amount of coal burned was used together with price of coal. The coal price was found by

matching Svalbard quality of coal with similar coal reserves [33]. This is used to calculate yearly

cost of coal, shown in Table 6.7.

Table 6.7: Estimated yearly cost of coal.

Coal consumption

Coal price [$/short ton] 65.5

Coal price [$/ton] 72.2

Coal consumption [ton/year] 60000

Coal costs per year $ 4 332 000

Coal costs per year NOK 25 125 700

6.2.4 Operation and Maintenance

Yearly operation and maintenance costs were calculated using statistical analysis of financial

performance of earlier power plants [34], giving the estimated costs in Table 6.8.

Table 6.8: Estimated yearly costs of operation and maintenance.

Operations and Maintenance costs

O&M [$/kW] 71 electric [kW] 13421.5

Total O&M costs [$/year] $ 952 900

Total O&M costs [NOK/year] NOK 5 527 000


31

6.2.5 Chemicals

The estimation of yearly costs for chemicals was obtained by scaling of a PC plant with a carbon

capture facility [8]. The results are summarized in Table 6.9.

Table 6.9: Estimated yearly costs of chemicals. This includes carbon, MEA solvent, lye, corrosion inhibitor, ammonia and other chemicals.

Cost of Chemicals

Chemicals [$/kWh] $ 0.00359 electric [kW] 13421.5

W [kWh] 117572753

Total O&M costs [$/year] $ 422 100

Total O&M costs [NOK/year] NOK 2 448 100

6.2.6 Total Variable Costs

By adding all the variable costs, the total yearly variable cost is estimated to be OK 47 1 00.

6.3 Revenues It is assumed that the price of electricity on Svalbard is 1.00 NOK/kWh, and that the price of

district heating is 0.50 NOK/kWh. The revenue is estimated in Table 6.10.

Table 6.10: Estimated yearly revenues.

Revenue

Price of electricity [NOK/kWh] [35] NOK 1.00

Price of district heating [NOK/kWh] [35] NOK 0.50

Total amount of electricity per year [kWh] 84 034 680

Total amount of district heating per year [kWh] 105 120 000

Revenue from electricity NOK 84 034 700

Revenue from district heating NOK 52 560 000

Total yearly revenue NOK 136 594 700

6.4 Working Capital The working capital was estimated as the cost of 60 days of raw material (coal and chemicals)

for production and 2% of the total fixed investment cost (for spare parts), as recommended by

NETL [8]. This estimation results in a working capital of NOK 40 673 800.

7 Investment Analysis The investment analysis was done by estimating net present value (NPV) and internal rate of

return (IRR) for each of the two cases (heat pump versus district heating). NPV was estimated

using the following formula [25]:

P FC ∑

(1 )

(12)

where is the cash flow in year , is the project life in years and is the interest rate in

percent/100. The IRR was calculated by setting equation (12) equal to zero, and solving for .

7.1 Base Case Figure 7.1 shows the estimated NPV as a function of years after investment, using the estimated

capital cost, variable costs, revenues and working capital: It has been assumed constant yearly


32

costs, a constant depreciation rate of 10%, a constant 20% amount depreciation and 0% tax on

Svalbard.

Figure 7.1: A plot showing the base case’s net present value as a function of years after investment with and without carbon capture and storage.

The IRR of the base case project was calculated to be 3.8% with carbon capture, and 11.1%

without carbon capture.

7.2 Heat Pump Case Figure 7.2 shows the estimated NPV as a function of years after investment using the estimated

capital cost, variable costs, revenues and working capital: It has been assumed constant yearly

costs, a constant depreciation rate of 10%, a constant 20% amount depreciation and 0% tax on

Svalbard.

-2500

-1500

-500

500

1500

2500

3500

4500

-1 2 5 8 11 14 17 20 23 26 29 32 35 38 41 44 47 50

Ne

t P

rese

nt

Va

lue

[M

NO

K]

Years after investment

Without Carbon Capture

With Carbon Capture


33

Figure 7.2: A plot showing the heat pump case’s net present alue as a unction o years a ter in estment

The IRR of the project was calculated to be 1.9%.

The IRR was also estimated for a case where no district heating is produced, and yielded an IRR

of 2.2% (which assumes that all the consumers will have to obtain their own heat pumps, or

some other form of heating).

8 Discussion

8.1 Plant Choices Many considerations have to be done regarding choice of plant. Weighing the high efficiency of

Integrated Gasification Combined Cycle (IGCC) plants against the in-development Chemical

Looping (CL) plants with simple carbon capture and storage (CCS) opportunities, or the already

conventional pulverized coal (PC) plant. Choice of steam cycle is also important, as number of

turbines and pressure levels highly affect the efficiency. Lastly, flue gas treatment has to be

discussed, where the different options are available at different prices.

8.1.1 Plant Type

While IGCC and CL plants were considered in the beginning, they were found unsuitable for the

planned project at Svalbard. These plants take advantage of size, as the air separation unit (ASU)

and catalyzed reactors come at a large capital and variable cost. If, however, the plant is large

enough, the ASU and reactor can repay themselves many-fold with the increased efficiency of the

plant [8]. Both options also put strains on equipment, especially so with pre-combustion

capture, where high purity hydrogen is combusted inside the turbine, yielding high

temperatures. Using a gas turbine for combined cycle puts a lot of strain on gas treatment, as the

turbines are sensitive to sulfur and carbon dioxide contents.

-3000

-2500

-2000

-1500

-1000

-500

500

1000

1500

-1 2 5 8 11 14 17 20 23 26 29 32 35 38 41 44 47 50

Net

Pre

sen

t V

alu

e [M

NO

K]

Years after investment


34

With its remote location, a power plant at Svalbard can easily find itself for long periods of time

without spare parts, making well-developed technology the preferred choice. Instead of in-

development technology, state of the art conventional technology was found to be the best fit. PC

plants fit this choice well, as the idea of burning coal to yield steam is over 200 years old [36]. In

a PC plant, the same principle applies, but the coal is pulverized into coal dust that burns more

efficiently. In Appendix E composite curves for the boiler are shown, proving that the design is

within the constraints of utilizable energy.

Steam turbine technology is well developed for PC plants, no gas turbine or reactor is required,

and air is blown into the boiler, without need for compression or cryogenic distillation. All of

these factors help keep the capital and variable costs low, giving a better investment perspective.

8.1.2 Steam Cycle

The current plant has a steam cycle design with two turbines, one of which is a condensing

turbine, and the other is a backpressure turbine used to produce district heating. The proposed

design has an extra turbine because they have a much higher steam pressure, as the current

technology has a maximum allowable pressure drop. It also permits for reheating in between

pressure levels which increases the efficiency [8]. A higher steam pressure also improves the

overall efficiency, which is evident in Figure 5.4.

The efficiency may be further improved by allowing a higher maximum pressure, but due to

support limitations on Svalbard, a more robust design was chosen. A higher steam temperature

may also have a positive effect, as can be seen in Figure 5.2.

8.1.3 Flue Gas Treatment

The plant has to be within Norwegian emission regulations, putting requirements on the dust

particles, sulfur, mercury and carbon dioxide output of the plant. As Svalbard already has plans

for a Flue Gas Desulfurization unit (FGD) using seawater, a seawater scrubber was used in the

design. A seawater scrubber is cheaper; both in capital cost, as the scrubber itself is cheap, and in

variable costs as seawater is considered to be free [21]. A seawater scrubber would also deal

with the mercury [23] and dust particles [8], which is harder to achieve using a dry scrubber

[21]. Alternatively an electrostatic filter could be used to remove dust particles and mercury

derivatives.

Svalbard also takes part in a project [37], aiming at a CO2-free Svalbard by 2025, which requires

the plant to have carbon dioxide capture and storage. As geological formations for storage exist

in close vicinity of Longyearbyen, the plan is feasible. At atmospheric pressure, amine solution is

preferred for capture, but puts further strain on the capital costs, as well as using heat from the

boiler as re-boiler duty. During economic evaluation, CSS capital costs were estimated as a worst

case scenario from Table 3.2, to be as much as 87% of the PC plant itself, with an electric power

penalty of up to 29%.

8.2 Case Studies

8.2.1 Base Case

In the base case, it is assumed that the current district heating network on Svalbard can be used,

which will reduce the capital cost significantly. District heating has the advantage of yielding

high overall plant efficiency, because most of this heat is not feasible for production of electrical

power. The current power plant was calculated, by Equation (4), to have an efficiency of 48.3%


35

(including diesel generators). The proposed design has an efficiency of 34.8%, which is quite

high considering that it includes carbon capture.

8.2.2 Steam Temperature

A case study was performed on the model in Aspen HYSYS, yielding results which point towards

a correlation that higher steam temperatures yield a higher power generation, and consequently

a higher thermal efficiency. These results apply only for the power plant modeled, and may vary

with varying steam cycles, boiler choices and plant size. Temperature considerations will have to

be done, as the higher temperature will lead to higher heat exchanger area in the boiler and

increased corrosion of the steam turbines [8]. Safety of the employees is also of concern, and risk

analysis is important for choosing a desired design.

8.2.3 Steam Cycle Pressure

A case study was performed on the model in Aspen HYSYS, yielding results which point towards

a correlation that higher pressure in the steam cycle gives a higher power generation, and

consequently a higher thermal efficiency. These results apply only for the power plant modeled,

and may vary with varying steam cycles, boiler choices and plant size. For the plant to use

supercritical and ultra-supercritical pressure, equipment and safety considerations will have to

be done. The increased capital cost from materials and complexity will have to be assessed. This

is especially true as ultra-supercritical steam generation is still under development, and not

available commercially [8]. It is still possible to build a pilot plant, but this will require a lot of

expertise and support, which might not be suitable at a remote location such as Svalbard.

8.2.4 Heat Pump Case

In the heat pump case, a central heat pump at the plant was considered. The heat pump would

provide hot water for the district heat network, and obtaining heat from the ocean. However,

since Svalbard has a cold climate, a seawater heat pump would not be viable. Nevertheless, this

option could become sustainable if geothermal heat is used instead of seawater. The efficiency of

the design with seawater as the heat source is calculated to be 34.3% which is lower than the

base case. In Figure 5.6, the efficiency is plotted against the coefficient of performance, and it is

apparent that even a high performance heat pump would yield rather low efficiency. Although,

higher than the base case with a sufficiently effective heat pump.

8.3 Investments

8.3.1 Cost estimations

In cost estimation of the PC boiler, it was assumed that capacity scaling was sufficient, as no

price for a boiler in the right capacity range was found. The boiler used for scaling was almost 50

times larger, which results in a high uncertainty. The steam turbine costs were estimated in an

equivalent manner, but with the scaling capacity much closer to the estimated steam turbine

capacities. The FGD and heat pump costs were also estimated using the aforementioned method,

and were assumed to moderately accurate, being inside a given capacity range.

Heat exchanger, compressor and pump costs were estimated using a slightly more accurate

method, as described earlier. However, the seawater pump were larger than the stated interval,

hence its cost estimation will be somewhat inaccurate.

The cost of the carbon capture facility was estimated as 87% of the total capital cost of the whole

plant (without carbon capture), the worst case scenario from Table 3.2. This estimate might be


36

too large, as there is a lot of ongoing research into improving the cost of carbon capture by

amine absorption.

The total fixed capital cost of the plant was calculated the factorial method presented earlier.

The factors were obtained from Sinnott [25], and might have some degree of uncertainty as the

expenses will be higher on a remote location such as Svalbard.

The cost of labor was estimated from the number of units on the plant. Only operators were

considered, and all other cost for other personnel (administrative, maintenance etc.) are not

included. This is fairly inaccurate, and the total labor cost will probably be higher.

The usage of diesel was assumed to be constant, which might be wrong as the new plant may

experience some difficulties during startup which will increase the need for backup power, and

consequently diesel.

It is assumed that the coal have to be bought at a relatively high price because the net calorific

value of the coal on Svalbard is high.

The cost of chemicals was estimated by scaling chemical requirements from a PC plant with CO2

capture, and might have some uncertainty associated with it, due to the fact that the plant used

for scaling is 50 times larger.

For the estimation of revenues it is assumed that the plant is operating at maximum capacity and

that all the electricity and heating produced will be bought by the consumers. This assumption is

inaccurate, as the electricity needed at Svalbard will not automatically double as soon as the new

plant is installed.

The working capital is estimated as 60 days of coal supply, and 2% of the total plant cost for

spare part etc. The National Energy Technology Laboratory recommends that only 0.5% of the

total plant cost is needed for spare parts, however, Svalbard is a remote location and it was

consequently assumed that it will need four times the amount of spare parts.

8.3.2 Investment analyses

The net present value (NPV) was estimated by assuming that the yearly expenses and revenues

are constant throughout the whole lifetime of the project. This is incorrect, but yields a good

indication o the project’s alue or comparing to other projects In Figure 7.1 and Figure 7.2 it is

evident that the base case has a larger NPV than the heat pump case, and will therefore be a

better investment. In Figure 7.1, the NPV for the base case without district heating is shown, and

it has a much higher NPV than the base case. This indicates that CCS is the economic bottleneck,

and it might be worthwhile to wait for more efficient technology to become readily available.

The base case has a higher internal rate of return than the heat pump case, which is also an

indication that it is the better investment. When it is assumed that the consumers obtain their

heat by some other form than district heating, a higher IRR is obtained, but this is still lower

than the base case. However, both cases have a huge NPV in the 50 year horizon-perspective,

and if a sufficiently efficient heat pump is developed, it may be worth the extra investment.


37

9 Conclusion and Recommendations A pulverized coal (PC) plant was found to be the best fit for a new power plant on Svalbard. The

technology is commercially available, and no research and development is required. Oxygen-

fired combustion is a lucrative option, as the carbon capture is more efficient, but it will have to

be developed further before being implemented at a secluded location as Svalbard.

A maximum boiler temperature of 00 was assumed, together with subcritical pressure in the

steam cycle. It is recommended to do further studies, as it was shown that increased

temperature and pressure gives higher efficiency. Supercritical pressures are already

conventional, but a plant at Svalbard needs to consider its isolated location. The boiler has been

greatly simplified; hence further studies are needed for obtaining actual combustion

temperature and heat exchanging possibilities.

District heating from a backpressure steam turbine was found to be a better option than a

central heat pump, both practically and economically. Even if consumers obtain their own heat

pumps, the base case is preferable.

Carbon capture and storage (CCS) is also a field largely in development. Price of equipment is

expected to fall, and efficiency is expected to rise. CCS is the bottleneck in both economical and

efficiency-wise for the power plant, and was studied further in another project.


38

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41

List of symbols and abbreviations Symbol Unit Description ASU Air Separation Unit $ Constant for Cost Estimation Constant for Cost Estimation $ Cost , , $ Purchased Cost of Equipment in Carbon Steel $ Total Fixed Capital Cost $ Cost of Plant with Capacity $ Cost of Plant with Capacity CC Carbon Capture CCS Carbon Capture and Storage CEPCI Chemical Engineering Plant Cost Index CL Chemical Looping COP Cost of Electricity DE $ Design and Engineering Cost FGD Flue Gas Desulfurization FGT Flue Gas Treatment Installation Factor for Civil Engineering Work Installation Factor for Electrical Work Installation Factor for Equipment Erection Installation Factor for Instrumentation and Process Control Installation Factor for Lagging, Insulation and Paint Installation Factor for Exotic Alloys Installation Factor for Piping Installation Factor for Structures and Buildings HEX Heat Exchanger HRSG Heat Recovery System Generator HP High Pressure IGCC Integrated Gasification Combined Cycle IP Intermediate Pressure IRR Internal Rate of Return LP Low Pressure Total Number of Pieces of Equipment MEA Monoethanolamine C g s Mass flow of Coal Number of Operators

Number of Units NCV cal g Net Colorific Value NGCC Natural Gas Combined Cycle NOK Norwegian Krone P MNOK Net Present Value Exponent Factor for Order of Magnitude OECD Organization for Economic Co-operation and Development O $ Offsite Costs O&M Operation and Maintenance Cost PC Pulverized Coal district heat MW Power provided to District Heating Capacity of Plant with Cost Capacity of Plant with Cost sC Subcritical SC Supercritical


42

Symbol Unit Description SCR Selective Catalytic Reduction U m K Overall Heat Transfer Coefficient electric MW Net Electric Power Produced X $ Contingency Cost i Mole Fraction of Component thermal Thermal Efficiency


A-1

Appendix A - Cost estimation for the base case

A.1 Cost of major equipment

The cost estimation of the major equipment is shown in Table A.1.

Table A.1: Cost estimation of the major equipment.

Boiler C2 = C1(S2/S1)^0.67*(I2/I1)

S2 [MW] 13.42154714

C1 $ 339 189 000.00

S1 [MW] 550

I2 630.2

I1 525.4

Capital Cost of Boiler $ 33 807 637.06

HP Turbine C2 = C1(S2/S1)^0.67*(I2/I1)

S2 [MW] 2.990730163

C1 $ 834 000.00

S1 [MW] 3

I2 657.7

I1 575.4

Capital Cost of HP Turbine $ 951 313.24

IP Turbine C2 = C1(S2/S1)^0.67*(I2/I1)

S2 [MW] 2.096839296

C1 $ 834 000.00

S1 [MW] 3

I2 657.7

I1 575.4

Capital Cost of IP Turbine $ 749 896.70

LP Turbine C2 = C1(S2/S1)^0.67*(I2/I1)

S2 [MW] 6.784556249

C1 $ 834 000.00

S1 [MW] 3

I2 657.7

I1 575.4

Capital Cost of LP Turbine $ 1 646 918.71

District Heat Exchanger (24000+46*A^1.2)*(I2/I1)

UA [W/K] 126061.1955

U [W/m2 K] 1200

A [m2] 105.0509963

I2 630.2

I1 525.4

Capital Cost of District Heat Exchanger $ 43 490.90


A-2

CO2 Cooler (24000+46*A^1.2)*(I2/I1)

UA [W/K] 15645.45174

U [W/m2 K] 50

A [m2] 312.9090347

I2 630.2

I1 525.4

Capital Cost of CO2 Cooler $ 83 268.56

Vacuum Condensers (24000+46*A^1.2)*(I2/I1)

UA [W/K] 4724201.521

U [W/m2 K] 1200

A [m2] 3936.834601

Number of condensers 4

A per condenser [m2] 984.2086503

I2 630.2

I1 525.4

Capital Cost per Condenser $ 244 288.95

Capital Cost of Vacuum Condensers $ 977 155.79

LP CO2 Cooler (24000+46*A^1.2)*(I2/I1)

UA [W/K] 21301.19111

U [W/m2 K] 100

A [m2] 213.0119111

I2 630.2

I1 525.4

Capital Cost of LP CO2 Cooler $ 63 129.62

IP CO2 Cooler (24000+46*A^1.2)*(I2/I1)

UA [W/K] 75330.38298

U [W/m2 K] 700

A [m2] 107.6148328

I2 630.2

I1 525.4

Capital Cost of IP CO2 Cooler $ 43 922.57

LP CO2 Compressor (490000+16800*P^0.6)*(I2/I1)

P [kW] 960.7527304

I2 913.9

I1 525.4

Capital Cost of LP CO2 Compressor $ 2 652 375.18

IP CO2 Compressor (490000+16800*P^0.6)*(I2/I1)

P [kW] 987.014704

I2 913.9

I1 525.4

Capital Cost of IP CO2 Compressor $ 2 681 738.22


A-3

HP CO2 Pump (6900+206*V^0.9)*(I2/I1)

q [l/s ] 7.801010982

I2 913.9

I1 525.4

Capital Cost of HP CO2 Pump $ 14 278.32

Main Water Pump (6900+206*V^0.9)*(I2/I1)

q [l/s ] 9.116187496

I2 913.9

I1 525.4

Capital Cost of Main Water Pump $ 14 620.95

LP Water Pump (6900+206*V^0.9)*(I2/I1)

q [l/s ] 4.768238621

I2 913.9

I1 525.4

Capital Cost of LP Water Pump $ 13 463.61

District Heat Water Pump (6900+206*V^0.9)*(I2/I1)

q [l/s ] 66.18057501

I2 913.9

I1 525.4

Capital Cost of District Heat Water Pump $ 27 595.24

Seawater Pump (6900+206*V^0.9)*(I2/I1)

qtot [l/s ] 2500.640907

I2 913.9

I1 525.4

Capital Cost of Seawater Pump $ 421 755.00

Flue Gas Desulfurization C*P*(I2/I1)

P [kW] 13421.54714

C [$/kW] 250

I2 692.9

I1 394.3

Capital Cost of Flue Gas Desulfurization $ 5 896 392.35

CO2 Removal C = x*C1*(I2/I1)

Capital Cost Without Carbon Capture [$] $ 156 035 250.47

Percent Increase with Carbon Capture 87 %

I2 499.6

I1 692.9

Capital Cost of CO2 Removal $ 97 879 973.57


A-4

Installation factors

Equipment erection factor, fer 0.5

Piping factor, fp 0.6

Instrumentation and Control factor, f i 0.3

Electrical factor, fel 0.2

Civil factor, fc 0.3

Structures and Building factor, fs 0.2

Lagging and Paint factor, fl 0.1

Material, fm: Carbon steel 1

Material, fm: Stainless steal 1.3

Boiler 1.2

HP Turbine 3.2

IP Turbine 3.2

LP Turbine 3.2

District Heat Exchanger 3.2

Vacuum Condenser 3.2

CO2 Cooler 3.68

LP CO2 Cooler 3.68

IP CO2 Cooler 3.68

LP CO2 Compressor 3.68

IP CO2 Compressor 3.68

HP CO2 Pump 3.68

Main Water Pump 3.2

LP Water Pump 3.2

District Heat Water Pump 3.2

Seawater Pump 3.68

Flue Gas Desulfurization 1

CO2 Removal 1


A-5

Installed Capital Costs

Boiler $ 40 569 164.47

HP Turbine $ 3 044 202.35

IP Turbine $ 2 399 669.44

LP Turbine $ 5 270 139.88

District Heat Exchanger $ 139 170.88

Vacuum Condenser $ 3 126 898.52

CO2 Cooler $ 306 428.31

LP CO2 Cooler $ 232 317.02

IP CO2 Cooler $ 161 635.05

LP CO2 Compressor $ 9 760 740.66

IP CO2 Compressor $ 9 868 796.65

HP CO2 Pump $ 52 544.21

Main Water Pump $ 46 787.03

LP Water Pump $ 43 083.55

District Heat Water Pump $ 88 304.78

Seawater Pump $ 1 552 058.42

Flue Gas Desulfurization $ 5 896 392.35

Offsites 0.4

Design and Engineering 0.25

Contingency 0.1

Total fixed capital cost (without CO2 removal) $ 156 035 250.47

NOK 905 004 452.10

Total fixed capital cost (with CO2 removal) $ 341 028 400.52

NOK 1 977 964 723.00

A.2 Variable costs

The estimation of the variable costs is shown in Table A.2.

Table A.2: Estimation of the variable costs.

Labor

Number of units 20


Shifts per day 6


Salary per year NOK 433 000.00

Labor costs per year NOK 10 392 000.00

Diesel consumption





Mean diesel consumption [l] 307584.75


Diesel costs per year NOK 3 691 017.00


A-6

Coal consumption




Coal costs per year $ 4 332 010.58

Coal costs per year NOK 25 125 661.38


O&M [$/kW] 71

P [kW] 13421.54714

Total O&M costs [$/year] $ 952 929.85

Total O&M costs [NOK/year] NOK 5 526 993.11

Cost of Chemicals

Chemicals [$/kWh] $ 0.00359

P [kW] 13421.5

W [kWh] 117572753



Total

Total variable costs [$/year] NOK 47 183 771.35

A.3 Revenues

The estimation of the yearly revenue is shown in Table A.3.

Table A.3: Estimation of the yearly revenue.

Revenue

Price of electricity [NOK/kWh] NOK 1.00

Price of district heating [NOK/kWh] NOK 0.50

Total amount of electricity [kWh] 84034680

Total amount of district heating [kWh] 105120000

Revenue from electricity NOK 84 034 680.00

Revenue from district heating NOK 52 560 000.00

Total revenue NOK 136 594 680.00

A.4 Working capital

The estimation of the working capital is shown in Table A.4.

Table A.4: The estimation of the working capital.

Working capital

Value of raw materials in inventory (60 days) NOK 1 114 538.70

Spare parts (2 % of total plant cost) NOK 39 849 181.64

Total Working Capital NOK 40 963 720.34


B-1

Appendix B - Cost estimation for the heat pump case

B.1 Major Equipment

The cost estimation of the major equipment is shown in Table B.1.

Table B.1: Cost estimation of the major equipment.

Boiler C2 = C1(S2/S1)^0.67*(I2/I1)

S2 [MW] 13.42154714

C1 $ 339 189 000.00

S1 [MW] 550

I2 630.2

I1 525.4



S2 [MW] 2.99386541

C1 $ 834 000.00

S1 [MW] 3

I2 657.7

I1 575.4

Capital Cost of HP Turbine $ 951 981.30


S2 [MW] 0

C1 $ 834 000.00

S1 [MW] 3

I2 657.7

I1 575.4

Capital Cost of IP Turbine $ -


S2 [MW] 12.65709666

C1 $ 834 000.00

S1 [MW] 3

I2 657.7

I1 575.4



UA [W/K] 0

U [W/m2 K] 1200

A [m2] 0

I2 630.2

I1 525.4

Capital Cost of District Heat Exchanger $ -


B-2


UA [W/K] 12261753.54

U [W/m2 K] 1200

A [m2] 10218.12795



I2 630.2

I1 525.4

Capital Cost per condenser $ 254 206.86

Capital Cost of Vacuum Condensers $ 2 542 068.57

CO2 Cooler (24000+46*A^1.2)*(I2/I1)

UA [W/K] 14777.81911

U [W/m2 K] 50

A [m2] 295.5563823

I2 630.2

I1 525.4

Capital Cost of CO2 Cooler $ 79 663.40

LP CO2 Cooler (24000+46*A^1.2)*(I2/I1)

UA [W/K] 22420.49441

U [W/m2 K] 100

A [m2] 224.2049441

I2 630.2

I1 525.4

Capital Cost of LP CO2 Cooler $ 65 306.34

IP CO2 Cooler (24000+46*A^1.2)*(I2/I1)

UA [W/K] 88258.8128

U [W/m2 K] 700

A [m2] 126.0840183

I2 630.2

I1 525.4

Capital Cost of IP CO2 Cooler $ 47 090.88

LP CO2 Compressor (490000+16800*P^0.6)*(I2/I1)

P [kW] 960.7527304

I2 913.9

I1 525.4

Capital Cost of LP CO2 Compressor $ 2 652 375.18

IP CO2 Compressor (490000+16800*P^0.6)*(I2/I1)

P [kW] 960.7527304

I2 913.9

I1 525.4

Capital Cost of IP CO2 Compressor $ 2 652 375.18


B-3

HP CO2 Pump (6900+206*V^0.9)*(I2/I1)

q [l/s ] 7.801010982

I2 913.9

I1 525.4

Capital Cost of HP CO2 Pump $ 14 278.32


q [l/s ] 8.895505456

I2 913.9

I1 525.4


LP Water Pump (6900+206*V^0.9)*(I2/I1)

q [l/s ] 0

I2 913.9

I1 525.4

Capital Cost of LP Water Pump $ -


q [l/s ] 0

I2 913.9

I1 525.4

Capital Cost of District Heat Water Pump $ -


qtot [l/s ] 3109.246726

I2 913.9

I1 525.4



P [kW] 13421.54714

C [$/kW] 250

I2 692.9

I1 394.3


CO2 Removal C = x*C1*(I2/I1)

Capital Cost Without Carbon Capture [$] $ 220 792 351.45

Percent Increase with Carbon Capture 87 %

I2 499.6

I1 692.9

Capital Cost of CO2 Removal $ 138 501 713.29


B-4

Central heat pump

Cost per kW [NOK/kW] NOK 14 000.00

Heat provided [kW] 12000

Capital Cost of Central heat pump NOK 168 000 000.00




Instrumentation and Control factor, fi 0.3







Boiler 1.2

HP Turbine 3.2

IP Turbine 3.2

LP Turbine 3.2



CO2 Cooler 3.68

LP CO2 Cooler 3.68

IP CO2 Cooler 3.68

LP CO2 Compressor 3.68

IP CO2 Compressor 3.68

HP CO2 Pump 3.68

Main Water Pump 3.2

LP Water Pump 3.2


Seawater Pump 3.68


CO2 Removal 1

Heat Pump 1


B-5


Boiler $ 40 569 164.47

HP Turbine $ 3 046 340.16

IP Turbine $ -

LP Turbine $ 8 003 254.32

District Heat Exchanger $ -


CO2 Cooler $ 293 161.31

LP CO2 Cooler $ 240 327.32

IP CO2 Cooler $ 173 294.44

LP CO2 Compressor $ 9 760 740.66

IP CO2 Compressor $ 9 760 740.66

HP CO2 Pump $ 52 544.21


LP Water Pump $ -

District Heat Water Pump $ -



Heat Pump $ 28 965 517.24

Offsites 0.4


Contingency 0.1


NOK 1 280 595 638.40

Total fixed capital cost (with CO2 removal) $ 482 560 589.57

NOK 2 798 851 419.53

B.2 Variable Costs

The estimation of the variable costs is shown in Table B.2.

Table B.2: Estimation of the variable costs

Labor

Number of units 18


Shifts per day 6




Diesel consumption









B-6

Coal consumption







O&M [$/kW] 71

P [kW] 13421.54714



Cost of Chemicals


P [kW] 13421.5

W [kWh] 117572753



Total

Total variable costs [NOK/year] NOK 47 183 771.35

B.3 Revenues

The estimation of the yearly revenue is shown in Table B.3.

Table B.3: Estimation of the yearly revenue.

Revenue



Total amount of electricity [kWh] 117412204


Heat pump COP 3

Electricity needed for heat pump 35040000

Available electricity 82372204




B.4 Working Capital

The estimation of the working capital is shown in Table B.4.

Table B.4: Estimation of the working capital

Working capital

Value of raw materials in inventory (60 days) NOK 1 114 538.70




C-1

Appendix C - Cost estimation for the base case without carbon capture

C.1 Cost of major equipment

The cost estimation of the major equipment is shown in Table C.1.

Table C.1: Cost estimation of the major equipment.

Boiler C2 = C1(S2/S1)^0.67*(I2/I1)

S2 [MW] 13.42154714

C1 $ 339 189 000.00

S1 [MW] 550

I2 630.2

I1 525.4



S2 [MW] 5.02153665

C1 $ 834 000.00

S1 [MW] 3

I2 657.7

I1 575.4

Capital Cost of HP Turbine $1 346 211.64


S2 [MW] 2.096839296

C1 $ 834 000.00

S1 [MW] 3

I2 657.7

I1 575.4

Capital Cost of IP Turbine $ 749 896.70


S2 [MW] 15.3701151285023

C1 $ 834 000.00

S1 [MW] 3

I2 657.7

I1 575.4



UA [W/K] 126061.1955

U [W/m2 K] 1200

A [m2] 105.0509963

I2 630.2

I1 525.4

Capital Cost of District Heat Exchanger $ 43 490.90


C-2


UA [W/K] 10702471.7025945

U [W/m2 K] 1200

A [m2] 8918.726419



I2 630.2

I1 525.4

Capital Cost per Condenser $ 246 066.61

Capital Cost of Vacuum Condensers $ 2 214 599.52


q [l/s ] 15.13710685

I2 913.9

I1 525.4


LP Water Pump (6900+206*V^0.9)*(I2/I1)

q [l/s ] 10.8022358

I2 913.9

I1 525.4

Capital Cost of LP Water Pump $ 15 053.08


q [l/s ] 66.18057501

I2 913.9

I1 525.4

Capital Cost of District Heat Water Pump $ 27 595.24


qtot [l/s ] 5665.09248

I2 913.9

I1 525.4



P [kW] 13421.54714

C [$/kW] 250

I2 692.9

I1 394.3



C-3




Instrumentation and Control factor, fi 0.3







Boiler 1.2

HP Turbine 3.2

IP Turbine 3.2

LP Turbine 3.2



Main Water Pump 3.2

LP Water Pump 3.2


Seawater Pump 3.68



Boiler $ 40 569 164.47

HP Turbine $ 4 307 887.24

IP Turbine $ 2 399 669.44

LP Turbine $ 9 115 414.95

District Heat Exchanger $ 139 170.88



LP Water Pump $ 48 169.87

District Heat Water Pump $ 88 304.78



Offsites 0.4


Contingency 0.1


NOK 799 069 719.38


C-4

C.2 Variable Costs

The estimation of the variable costs is shown in Table C.2.

Table C.2: Estimation of the variable costs

Labor

Number of units 10


Shifts per day 6




Diesel consumption








Coal consumption







O&M [$/kW] 71

P [kW] 13421.54714



Cost of Chemicals


P [kW] 13421.5

W [kWh] 117572753



Total

Total variable costs [NOK/year] NOK 32 441 701.69


C-5

C.3 Revenues

The estimation of the yearly revenue is shown in Table C.3.

Table C.3: Estimation of the yearly revenue.

Revenue



Total amount of electricity [kWh] 83771908.33


Heat pump COP 3

Electricity needed for heat pump 35040000

Available electricity 82372204




C.4 Working Capital

The estimation of the working capital is shown in Table C.4.

Table C.4: Estimation of the working capital

Working capital

Value of raw materials in inventory (60 days) NOK 770 351.56




D-1

Appendix D Net Calorific Value of the Coal on Svalbard The net calorific value and contents of the coal are shown in Figure D.1.

Figure D.1: Analysis of the coal on Svalbard, received from Jørn Myrlund at Longyear Energiverk.


E-1

Appendix E – Composite Curves

E.1 Boiler

The hot and cold composite curves of the pulverized coal boiler in the base case are shown in

Figure E.1.

Figure E.1: Plot of hot and cold composite curve for the pulverized coal boiler. The pinch temperature is set to 10

E.2 District Heat Exchanger

The hot and cold composite curve of the district heat exchanger in the base case are shown in

Figure E.2.

Figure E.2: Plot of hot and cold composite curve for the district heat exchanger.

0

100

200

300

400

500

600

700

800

0 10 20 30 40 50 60

Te

mp

era

ture

[

Heat [MW]


Hot Composite Curve

0

50

100

150

200

250

300

350

400

0 1 2 3 4 5 6 7 8 9 10 11 12

Te

mp

era

ture

[

Heat [MW]


Hot Composite Curve


E-2

E.3 Vacuum Condenser

The hot and cold composite curves of the vacuum condenser in the base case are shown in

Figure E.3.

Figure E.3: Plot of hot and cold composite curve for the condenser.

E.4 CO2 Cooler

The hot and cold composite curves of the CO -Cooler in the base case are shown in Figure E.4.

Figure E.4: Plot of hot and cold composite curve for the CO -Cooler.

0

1

2

3

4

5

6

7

0 1 2 3 4 5 6 7 8 9 10 11 12

Te

mp

era

ture

[

Heat [MW]


Hot Composite Curve

0

10

20

30

40

50

60

70

80

90

0 0.05 0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45

Te

mp

era

ture

[

Heat [MW]


Hot Composite Curve


E-3

E.5 LP CO2-Cooler

The hot and cold composite curves of the LP CO -Cooler in the base case are shown in Figure

E.5.

Figure E.5: Plot of hot and cold composite curve for the LP CO -Cooler.

E.6 IP CO2-Cooler

The hot and cold composite curves of the LP CO -Cooler in the base case are shown in Figure

E.6.

Figure E.6: Plot of hot and cold composite curve for the LP CO -Cooler.

0

20

40

60

80

100

120

140

160

180

0 0.2 0.4 0.6 0.8 1 1.2

Te

mp

era

ture

[

Heat [MW]


Hot Composite Curve

0

20

40

60

80

100

120

140

160

180

200

0 0.5 1 1.5 2 2.5 3 3.5

Te

mp

era

ture

[

Heat [MW]


Hot Composite Curve


F-1

Appendix F – Aspen HYSYS Flowsheets

F.1 Base Case

Figure F.1: A larger image of the Aspen HYSYS flowsheet.


F-2

F.2 Heat Pump Case

Figure F.2: A larger image of the Aspen HYSYS flowsheet.

tkp4170 – process design, projectreport: 42 appendices: 23 conclusion a pulverized coal (pc) plant...

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